1. Field of the Invention
Embodiments disclosed herein relate generally to methods of increasing the fracture resistance of low permeability formations.
2. Background Art
During the drilling of a wellbore, various fluids are typically used in the well for a variety of functions. The fluids may be circulated through a drill pipe and drill bit into the wellbore, and then may subsequently flow upward through wellbore to the surface. Common uses for well fluids include: lubrication and cooling of drill bit cutting surfaces while drilling generally or drilling-in (i.e., drilling in a targeted petroliferous formation), transportation of “cuttings” (pieces of formation dislodged by the cutting action of the teeth on a drill bit) to the surface, controlling formation fluid pressure to prevent blowouts, maintaining well stability, suspending solids in the well, minimizing fluid loss into and stabilizing the formation through which the well is being drilled, fracturing the formation in the vicinity of the well, displacing the fluid within the well with another fluid, cleaning the well, testing the well, transmitting hydraulic horsepower to the drill bit, fluid used for emplacing a packer, abandoning the well or preparing the well for abandonment, and otherwise treating the well or the formation.
Wellbore fluids may also be used to provide sufficient hydrostatic pressure in the well to prevent the influx and efflux of formation fluids and wellbore fluids, respectively. When the pore pressure (the pressure in the formation pore space provided by the formation fluids) exceeds the pressure in the open wellbore, the formation fluids tend to flow from the formation into the open wellbore. Therefore, the pressure in the open wellbore is typically maintained at a higher pressure than the pore pressure. While it is highly advantageous to maintain the wellbore pressures above the pore pressure, on the other hand, if the pressure exerted by the wellbore fluids exceeds the fracture resistance of the formation, a formation fracture and thus induced mud losses may occur. Further, with a formation fracture, when the wellbore fluid in the annulus flows into the fracture, the loss of wellbore fluid may cause the hydrostatic pressure in the wellbore to decrease, which may in turn also allow formation fluids to enter the wellbore. As a result, the formation fracture pressure typically defines an upper limit for allowable wellbore pressure in an open wellbore while the pore pressure defines a lower limit. Therefore, a major constraint on well design and selection of drilling fluids is the balance between varying pore pressures and formation fracture pressures or fracture gradients though the depth of the well.
A particularly challenging situation arises in depleted reservoirs, in which pressure depleted formations are neighbored by or inter-bedded with normally or abnormally pressured zones. For example, high permeability pressure depleted sands may be neighbored by high pressured low permeability rocks, such as shale or high pressure sands. This can make the drilling of certain depleted zones nearly impossible because the mud weight required to support the shale exceeds the fracture resistance of the pressure depleted sands and silts.
Thus, wellbore strengthening techniques, ranging from use of cements, resins, casing drilling, and managed pressure drilling, etc, have seen recent increases in application and further development. In the drilling of the depleted zones described above, wellbore strengthening techniques have been used in hopes of increasing the fracture resistance of weaker formations, which may allow for more efficient and economic drilling.
Accordingly, there exists a continuing need for developments in wellbore strengthening.